Considerable cost savings can be attained by the use of clad and lined materials compared to solid Corrosion Resistant Alloy (CRA) materials. This is particularly evident with larger outside diameters CRA tubulars which are necessary to satisfy flow rate requirements and evident with heavier wall thicknesses which are required for strength and pressure requirements for specific downhole applications. CRA tubulars provide the corrosion resistance needed when gas drilling and completion operations involve severe downhole conditions where CO2 and H2S are present. These alloys are utilized when the traditional stainless steels do not provide adequate corrosion resistance. Over the last ten years, CRA tubulars, made out of nickel-based alloys like 825, G3, G50, C276 and 625 have met the material requirements for these wells, but the cost of these tubulars is exorbitant. Recent advances in technology have facilitated the development of a clad tubulars for downhole use composed of an API C90 and T95 outer tube and a CRA corrosion resistant liner. The carbon alloy, C90 or T95 outer tube, provides the structural integrity of the tubular while the CRA liner provides the necessary corrosion resistance. C90 and T95 are AISI 4130 type steel that is quenched (water) and tempered and is suitable for sour service environments per the guidelines in NACE MR0175-2000. CRA's are defined as those alloys whose mass-loss corrosion rate in produced fluids is at least an order of magnitude less than carbon steel, thus providing an alternative method to using inhibition for corrosion control. Table 1 shows the composition of various nickel-based CRA grades that are utilized for maximum corrosion resistance in aqueous H2S and CO2 environments. The mode of cracking in nickel-based alloys is occasionally intergranular.
TABLE 1CRA Alloy CompositionsALLOY Other-(UNS No.)CrNiMoFeMnC-MaxCb + TaMax825 (N08825)22423Bal0.50.03.9 Ti, 2 Cu925 (N088925)19/21.024/28.06/7.0 Bal1.0 Max0.021.5 Cu725 (N088725)21588Bal0.250.02625 (N08625)22Bal920.20.053.5Cb G3 (N06985)21/23.5Bal6/8.0 18/21.01.0 Max0.015.50 Max2.5 Cu, 2.4 WG30 (N06030)28/31.5Bal4/6.0 13/17.01.5 Max0.03.3/1.54.0 WG50 (N06050)19/21.050.0 Min8/10.015/20.01.0 Max0.015.50 Max2.5 CoC276 (N010276)15Bal166—0.012 Co, 3.5 W
When CO2 is present in the flow stream, additional corrosion considerations are necessary. The presence of CO2 can considerably increase the weight loss corrosion of carbon and alloy steel tubing. The corrosion rate is a function of the temperature, CO2 concentration and the partial pressure. Since regulatory and environmental guidelines usually prohibit the allowance for predictable weight loss corrosion (e.g., increasing the wall thickness to compensate for corrosion through the wall of the pipe), the selection of alternate stainless steel and CRA materials are made. When H2S is present, the corrosion problem switches from a weight loss issue (e.g., pitting and crevice corrosion) to a sulfide stress cracking (SSC) phenomena. Hydrogen sulfide stress cracking (SSC) is defined as the spontaneous fracturing of steel that is simultaneously subjected to an aqueous corrosive hydrogen sulfide medium and a static stress less than the tensile strength of the material. It usually occurs in a brittle manner, resulting in catastrophic failures at stresses less than the yield strength of the material. Hydrogen SSC is basically a hydrogen embrittlement mechanism resulting from the formation of hydrogen ions (H+) in the presence of aqueous hydrogen sulfide (H2S). Over the last five years, there has been an increasing need for downhole tubing suitable for severe CO2 and H2S environments. Numerous nickel-based alloys have well established corrosion resistant attributes for these production applications but are extremely costly when utilized as a solid wall tubular. The exorbitant cost of solid wall CRA tubulars has resulted in many projects being deemed too costly or postponed and therefore have not been pursued.